OGJ Newsletter

Aug. 21, 2017
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

OPEC output climbed 173,000 b/d in July

Total crude oil production from the Organization of Petroleum Exporting Countries increased 173,000 b/d month-over-month in July to average 32.87 million b/d, according to five secondary sources used in the cartel's August Monthly Oil Market Report.

Preliminary data indicate that global oil supply increased 170,000 b/d month-over-month in July to average 97.3 million b/d.

Libya output gained 154,000 b/d from June to just more than 1 million b/d. Nigeria rose 34,300 b/d to 1.75 million b/d. Both countries were exempted from the deal by OPEC and certain non-OPEC members to collectively curb output, but Nigeria recently agreed to cap its output at 1.8 million b/d.

Saudi Arabia, the leader of the output curtailment deal, lifted its output by 31,800 b/d from June to 10.07 million b/d. Smaller increases were also seen from Iran, Equatorial Guinea, Ecuador, Gabon, and Qatar.

Production from Iraq fell 33,100 b/d from June to 4.47 million b/d. Angola dropped 19,300 b/d to 1.65 million b/d. Venezuela declined 15,800 b/d to 1.93 million b/d. Smaller decreases were seen from Kuwait, UAE, and Algeria.

OPEC said non-OPEC supply rose 520,000 b/d in July to average 64.49 million b/d, mainly driven by Canada, Norway, the US, OPEC NGLs, Ghana, Colombia, Brunei, and Congo, which partially offset declines in the UK, China, Mexico, and Azerbaijan.

OPEC revised down forecast non-OPEC oil supply growth for 2017 by 28,000 b/d to 780,000 b/d, representing total non-OPEC supply of 57.77 million b/d.

Global oil demand is projected to average 96.49 million b/d in 2017, with demand growth expected at 1.37 million b/d following an upward revision of 100,000 b/d mainly reflecting better-than-expected second-quarter data from regions in the Organization for Economic Cooperation and Development, OPEC says.

ESAI 5-year oil outlook sees tenuous balance

In its recent Five-Year Outlook, ESAI Energy points out that the call on Organization of Petroleum Exporting Countries crude will remain under tremendous pressure over the next 5 years.

The outlook projects non-OPEC supply of crude oil and condensate to add about 2.3 million b/d to global supplies. Seventy percent of that growth will come from the US despite a slowdown in shale growth on the horizon. Non-OPEC NGLs and alternative fuels will add another 1.9 million b/d of supply. NGL supply from OPEC will add another 900,000 b/d.

Meanwhile, growth in total global oil demand is slowly decelerating as low oil prices have supported demand in several sectors, especially government stocking and petrochemicals. But, most of the petrochemical-led growth is met with gas-derived products. Thus, growth in demand for crude-derived products is actually slowing more quickly, ESAI said.

Modest crude-derived demand and continued non-OPEC expansion will complicate matters for OPEC even as the market rebalances. ESAI Energy Principal Sarah Emerson concludes, "If OPEC wants to keep oil prices in the $50s and hit $60, the organization will have to keep a lid on supply for several more years."

DOE to announce new sales of crude from SPR

The US Department of Energy expects to issue a notice of sale of crude oil from the Strategic Petroleum Reserve later in August, DOE's Fossil Energy Office said on Aug. 15. The anticipated sale of 14 million bbl will fulfill requirements of Section 5010(a)(1)(B) of the 21st Century Cures Act (Public Law 114-255) and Section 403(a)(1) of the Bipartisan Budget Act of 2015 (Public Law 114-74), FEO said.

It said that under Section 5010 of the 21st Century Cures Act, signed on Jan. 4, 2016, the secretary of energy is directed to draw down and sell a total of 25 million bbl of crude from the SPR over 3 consecutive fiscal years beginning in fiscal 2017. Of this amount, DOE will sell 9 million bbl in fiscal 2018. Revenues from the sale will go to the general fund of the US Department of the Treasury to carry out the National Institutes of Health's innovation projects.

Under Section 403 of the Bipartisan Budget Act of 2015, signed on Nov. 2, 2015, the US Energy Secretary is directed to draw down and sell a total of 58 million bbl of crude from the SPR over 8 consecutive fiscal years, starting in 2018. Of this amount, DOE will sell 5 million bbl in fiscal 2018, FEO said.

Any company registered in the SPR's Crude Oil Sales Offer Program is eligible to participate, it noted. Others may register at the SPR web site's Crude Oil Sales Offer Program, according to FEO.

FERC regains quorum: Chatterjee, Powelson sworn in

The US Federal Energy Regulatory Commission regained its quorum after 6 months as its two newest members, Neil Chatterjee and Robert F. Powelson, were sworn in on Aug. 8 and 10, respectively.

Chatterjee became chairman on Aug. 10 until the US Senate can confirm another nominee, Kevin McIntyre, who is in line for the position, when it returns from its August recess. The Senate also is expected to vote on an additional nominee, Richard Glick, at that time.

Chatterjee immediately announced that FERC will resume its monthly open meetings on Sept. 20, and the commission soon will begin to vote notationally on orders that have accumulated since it lost its quorum when member Norman C. Bay's resignation became effective on Feb. 1.

FERC's fifth member, Cheryl A. LaFleur, became acting chairman at that time and the independent federal regulatory agency acted under limited delegated authority. The delegation period, which began Feb. 1, will end on Aug. 24, 14 days after FERC's quorum was reestablished.

Exploration & DevelopmentQuick Takes

Uruguay to open third offshore bidding round

Uruguay is calling for bids on 17 areas in three offshore basins offered in the country's Round 3. According to Uruguayan National Oil Co. (ANCAP) and the Ministry of Industry, Energy, and Mining (MIEM), bathymetries range from 50-4,000 m of water.

Areas will be divided in Types I, II, and III according to water depth. The government's latest round will have 8-year exploration periods for areas Types I and II. Deepwater areas, Type III, will feature a 10-year exploration period. Contract terms are 30 years, including the exploration period, and can be extended an additional 10 years.

Uruguay Round 3 will make official announcements in Houston on Sept. 18 and in London on Oct. 20. Bidding round terms and the contract model for Uruguay's Round 3 will be like the country's Round 2 but with less rigorous requirements regarding the oil company qualification with regards to the required exploratory program for each area, ANCAP said.

The deadline for qualifying submissions is Apr. 6, 2018, and the opening of offers is Apr. 26.

GeoPark, Wintershall make oil find in Neuquen basin

GeoPark Ltd. and Wintershall Energia SA plan further tests of a discovery in Argentina's Neuquen basin with potential net pay of 400 ft in multiple strata.

The GeoPark Rio Grande West 1, drilled to 5,500 ft on CN-V block, has flowed 300 b/d of 28° gravity oil naturally with 7% water during early tests of four reservoir sands. It targeted the Lower Cretaceous Neuquen Group.

GeoPark says the well indicated 15 potential reservoir sands below 1,800 ft.

The partners are currently evaluating subsequent activities on the block, including a development plan for Rio Grande West.

CN-V block is in Mendoza province and covers 117,000 acres, with 3D seismic coverage of 180 sq km next to the producing Loma Alta Sur oil field operated by YPF SA. The block also has upside potential in the developing Vaca Muerta unconventional play, GeoPark says.

Interest in CN-V is split 50-50 between the companies. Wintershall has the right to take over operatorship pursuant to the terms and conditions of its 2015 farm-in agreement with GeoPark.

GeoPark's Argentina work program for 2017 includes seven gross wells, at a total cost of $5-7 million, that are expected to be drilled in the second half targeting shallow heavy oil exploration prospects in the Neuquen basin's Sierra del Nevado and Puelen blocks operated by Pluspetrol SA.

Puelen block is north of the producing El Corcobo oil field operated by Pluspetrol, and Sierra del Nevado is east of Llancanelo oil field operated by YPF.

Wintershall, meanwhile, has invested about $1 billion in Argentina over the past 3 years.

Rockhopper updates Al Jahraa drilling campaign

Rockhopper Exploration PLC's Al Jahraa-9 well has encountered the deepest known oil shows in the Abu Roash-D and Abu Roash-E (AR-E) reservoirs in Al Jahraa oil field onshore Egypt in the company's Abu Sennan drilling concession. The Al Jahraa-9 penetrated 5 m of reservoir sand in the primary Abu Roash-C (AR-C) reservoir.

The company also confirmed that wireline logging tested water wet sand but said reservoir pressure was in line with the producing AR-C reservoir in Al Jahraa and Al Jahraa SE fields. Rockhopper Chief Executive Officer Sam Moody expressed disappointment in the water wet sand but said "deep oil shows are an encouraging indication of the additional potential at these deeper levels in other areas of the concession."

The company is now integrating results of the Al Jahraa-9 well with existing data for Al Jahraa and Al Jahraa SE oil fields to help refine future development plans for these fields.

The operator's Al Jahraa SE-2X well was side-tracked into the Al Jahraa SE field, and wireline logging confirmed oil pays in both the AR-C and AR-E reservoirs. According to Rockhopper, the well has been completed in the deeper AR-E reservoir and is producing a pump-constrained 250 boe/d.

The operator's two-well campaign was launched in April 2017. The company holds a 22% interest in the Abu Sennan concession. Production from six fields have remained stable with an average 3,300 boe/d gross during first-half 2017, the company said.

Drilling & ProductionQuick Takes

Juniper gas production starts off Trinidad and Tobago

BP PLC's Trinidad and Tobago unit has reported the startup of its fifth major upstream project for 2017. BP Trinidad & Tobago's (BPTT) Juniper development has begun production of natural gas offshore the twin-island Caribbean nation.

The project is expected to boost BPTT's gas production capacity by 590 MMscfd and allow the company to meet its commitment to maintain its production from Trinidad and Tobago at more than 2 bscfd of gas.

BPTT said the project cost $2 billion and that Juniper is its first subsea field development in Trinidad and Tobago. It will produce gas from Corallita and Lantana fields via the new Juniper platform, 50 miles off the twin-island nation's southeast coast. The gas is being produced on the continental shelf in 110 m of water. BPTT said the gas will flow to its Mahogany B hub via a 10-km flowline that was installed in 2016.

Bernard Looney, chief executive of BP's upstream business, called Juniper a "major milestone" in BP's 50-year history in Trinidad and Tobago. "It is the largest new project brought into production in Trinidad [and Tobago] for several years and the second major project we have started here this year," Looney said.

Juniper's startup is expected to assist with the gas shortages that the twin-island nation has suffered over the last 3 years that has hurt its downstream production of methanol, ammonia, and urea and has led to Atlantic LNG producing at 80% capacity.

BPTT noted that the Trinidad Onshore Compression project, which is another of its major projects on the island, began operations in April. And in June, BPTT reported that it had sanctioned development of the Angelin gas field, which is expected to start production in late 2019. BPTT also announced two gas discoveries that may support future developments offshore.

Woodside's Persephone gas field brought on stream

The Woodside Petroleum Ltd.-operated North West Shelf joint venture has begun production from Persephone gas-condensate field in the Carnarvon basin off Western Australia.

Development of the field, in 125 m of water in licence WA-1-L about 135 km northwest of Karratha, was completed about 6 months ahead of schedule and 30% under budget.

The $1.2-billion (Aus.) project comprises two wells tied into a subsea production manifold and a 7-km flowline taking the gas and condensate to the existing North Rankin facilities that are integral to the North West Shelf gas project sending gas and liquids via dual export pipelines to the onshore LNG-domestic gas plant at Karratha.

Production from Persephone is expected to ramp up to about 290 MMcfd of gas.

The field was discovered in 2006 with Persephone-1 8 km northeast of the North Rankin Complex. The project was approved for construction in 2014.

Woodside is operator for the project. The JV partners are BP PLC, BHP Billiton Ltd., Chevron Corp., Royal Dutch Shell PLC, and Mitsubishi Corp.- Mitsui & Co. Ltd. Each company has a 16.67% interest.

Woodside to shut down Enfield oil field

Perth-based Woodside Petroleum Ltd. has begun the process of shutting down and decommissioning its Enfield oil field on the North West Shelf off Western Australia.

The company has submitted an environmental plan for the work with the Australian National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) to cease production, decommission, dismantle, and remove facilities from the field, which lies in licence WA-28-L in the Carnarvon basin about 50 km northwest of Exmouth.

The field was developed using subsea wells, manifolds, and flowlines tied back to the Nganhurra floating production, storage, and offloading vessel. It has been on stream since 2006.

The plan calls for Woodside to flush the subsea and topside infrastructure prior to disconnecting the FPSO from the field. The riser turret mooring will also be removed.

This will involve first plugging and abandoning the subsea wells, disconnection of the risers and electrohydraulic umbilical, removal of the buoyancy modules, and disconnection of the mooring lines from the riser mooring.

Plugging and abandonment of remaining wells and decommissioning of remaining subsea equipment will be subject to future stakeholder consultations and submission of more environmental plans.

NOPSEMA's decision about the environmental submission is expected at the beginning of September.

Woodside is operator of the field and is partnered by Mitsui E&P Australia.

Transocean to buy Songa Offshore for $1.8 billion

Transocean Ltd. plans to buy Songa Offshore SE for $1.8 billion subject to certain conditions. Terms call for the transaction to be paid mostly in stock and convertible bonds.

After closing, Transocean would acquire more equipment for drilling in harsh climates, including the Arctic. Four Songa rigs have long-term contracts with Statoil ASA. Songa has seven semisubmersible rigs total.

This was the latest drilling contractor consolidation.

Separately, Ensco PLC in May agreed to acquire Atwood Oceanics Inc. in a stock transaction worth $839 million.

In March, Transocean sold some shallow water jack up rigs to Norway's Borr Drilling. Transocean has said it wants to concentrate on deepwater and ultradeepwater drilling.

PROCESSINGQuick Takes

Shell begins restart of Pernis refinery

Shell Nederland Raffinaderij BV has initiated what will be a phased restart of its 404,000-b/d Pernis refinery and integrated petrochemical production site in Rotterdam, the Netherlands, following a July 29 power outage that led to a fire and subsequent shutdown of the manufacturing site.

Shell, which began recommissioning supporting units at the site on Aug. 8, expects Pernis will be back to full and normal operations within the next few weeks, said Jos van Winsen, the refinery's general manager.

The company will continue the gradual and controlled restart of remaining processing plants in the coming weeks upon receiving state-of-fitness approvals on startup plans for each individual unit from DCMR Milieudienst Rijnmond, South Holland province's joint environmental protection agency.

While Shell and DCMR continue to investigate both the July 29 incident as well as a subsequent release of hydrogen fluoride that occurred at the refinery on July 31, the investigation teams have confirmed that neither of the upsets were caused by overdue maintenance, said van Winsen.

The Pernis facility has a permanent team of 120 on-site inspectors to monitor and control processing units, pipelines, and other installations, van Winsen told concerned community members at a meeting to address the recent events.

The operator has yet to determine a detailed timeline for full recommissioning of operations at the site.

Shell sheds 50% stake in SADAF chemicals JV

Royal Dutch Shell PLC has completed the sale of its 50% interest in the Saudi Petrochemical Co. (SADAF) joint venture to Saudi Basic Industries Corp. (SABIC), its partner, for $820 million.

Part of Shell's broader $30-billion divestment program, the chemical sale enables the company to more finely focus its downstream activities and make selective investments to support growth of its global chemicals business, Shell said on Aug. 16.

With the transaction now finalized, SABIC plans further investments at SADAF both to optimize and integrate operations of the complex with other SABIC affiliates, according to Shell.

The SADAF complex, on 460 acres in Jubail, Saudi Arabia, comprises an ethylene plant, two styrene plants, a salt plant, an ethyl chloride-caustic plant, a methyl tertiary butyl ether plant, and a cogeneration plant.

It produces an average of more than 4 million tonnes/year of chemicals from ethane, benzene, methane, butane, and salt brine.

SABIC and Shell formed the joint venture in June 1980. Ethylene production began in October 1984.

The JV agreement was to have expired in 2020.

Delaware basin gas plant, gathering system planned

3Bear Energy LLC, Denver, has entered into definitive agreements with an unidentified anchor shipper to develop, own, and operate a gathering and processing system for oil, natural gas, and water production to serve Permian producers in the northern Delaware basin of Lea and Eddy Counties, NM.

Alongside more than 100 miles of pipeline wellhead gathering for oil, gas, and water transportation, 3Bear Energy is building a central water treatment plant, a crude terminal, and a 60-MMcfd cryogenic natural gas processing plant with treating capabilities, the company said.

With an expandable design to accommodate the rapid production growth in the Delaware basin, the system is scheduled to begin operations in first-quarter 2018.

Backed by long-term partner GSO Capital Partners LP, the credit investment arm of The Blackstone Group LP, New York, 3Bear Energy did not reveal further details regarding the proposed development.

TRANSPORTATIONQuick Takes

IOC begins importing US crude

Indian Oil Corp. Ltd. said its first cargo of US crude oil is expected to arrive in eastern India by Oct. 1.

The Bergitta crude oil tanker was recently loaded in South Louisiana with 2 million bbl of "high-sulphur Mars crude oil." Following a transfer to the New Prosperity crude tanker, the crude has a destination of Paradip, Odisha.

State-owned Indian Oil also said it bought a second cargo of 1.9 million bbl of US crude of Mars and Eagle Ford grades for delivery on the west coast at Vadinar, Gujarat, in early November.

India eased regulations on crude imports last year.

Indian Oil, which controls 11 of India's 23 refineries, said the import effort is a "big leap" aimed at diversifying its crude oil sources and boosting the country's energy security.

Andeavor starts work on Conan crude gathering system

Construction is under way on Andeavor's 130-mile Conan crude oil gathering pipeline system in the Permian's Delaware basin.

The Conan system will transport crude from origins in Lea County, NM, and Loving County, Tex., to a terminal to be constructed in Loving County, Tex., where the gathering system interconnects with long-haul pipeline carriers.

The first phase of the Conan system will provide capacity of 250,000 b/d. Future phases of the system may expand capacity up to 500,000 b/d.

The system is expected to begin commercial service in mid-2018. Estimated capital investment for the first phase of the gathering system is $225 million, of which $75 million is expected to be spent in 2017.